Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel), coal, shale, or porous rock. Production of natural gas from these types of formations typically involves drilling a well a desired depth into the formation, installing a casing in the wellbore (to keep the well bore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow into the casing, and installing a string of tubing inside the casing down to the production zone. Gas can then be made to flow up to the surface through a production chamber, which may be either the tubing or the annulus between the tubing and the casing.
Formation liquids, including water, oil, and/or hydrocarbon condensates, are generally present with natural gas in a subsurface reservoir. For reasons explained in greater detail hereinafter, these liquids must be lifted along with the gas. In order for this to happen, one of the following flow regimes must be present in the well:
Pressure-Induced Flow
                In a pressure-induced flow regime, the formation pressure (i.e., the pressure of the fluids flowing into the well) is greater than the hydrostatic pressure from the column of fluids (gas and liquids) in the production chamber. In other words, the formation pressure is sufficient to lift the liquids along with the gas. Pressure-induced flow occurs in wells producing from reservoirs having a non-depleting pressure; i.e., where the reservoir pressure is high enough that production from the reservoir results in no significant drop in formation pressure. This type of flow regime is common in reservoirs under water flood or having an active water drive providing pressure support. Conventional gas lift technology may be used to enhance flow in a pressure-induced flow regime by lightening the hydrostatic weight of total fluids in the production chamber.        Pressure-induced flow is most commonly associated with wells that are primarily oil-producing wells, and is rarely associated with primarily gas-producing wells.Velocity-Induced Flow        This type of flow occurs with gas reservoirs having a depleting pressure, and it is common in most gas reservoirs and all solution-gas-driven oil reservoirs. The present invention is concerned with velocity-induced flow, a general explanation of which follows.        In order to optimize total volumes and rates of gas recovery from a gas reservoir, the bottomhole flowing pressure should be kept as low as possible. The theoretically ideal case would be to have a negative bottomhole flowing pressure so as to facilitate 100% gas recovery from the reservoir, resulting in a final reservoir pressure of zero.        When natural gas is flowing up a well, formation liquids will tend to be entrained in the gas stream, in the form of small droplets. As long as the gas is flowing upward at or above a critical velocity (or “VCR”—the value of which depends on various well-specific factors), the droplets will be lifted along with the gas to the wellhead, where the gas-liquid mixture may be separated using well-known equipment and methods. In this situation, the gas velocity provides the means for lifting the liquids; i.e., the well is producing gas by velocity-induced flow.        The critical velocity VCR for a given wellbore will be dependent on a number of factors which may vary from one wellbore to the next, and which are subject to change over the life of the wellbore. Such factors may include, but are not necessarily limited to, reservoir pressure, flow line pressure, liquid production rate, liquid composition, gas composition, and wellbore design.        
Formation pressures in virgin reservoirs of natural gas tend to be relatively high. Therefore, upon initial completion of a well, the gas will commonly rise naturally to the surface by velocity-induced flow provided that the characteristics of the reservoir and the wellbore are suitable to produce stable flow (meaning that the gas velocity at all locations in the production chamber remains equal to or greater than the critical velocity, VCR—in other words, velocity-induced flow). Typically these wells will flow with excess velocity (i.e., significantly greater than VCR), resulting in friction between the flowing fluids and the production chamber.
As gas reserves are removed, the formation pressure drops continuously, resulting in reduced fluid velocities in the wellbore. Lower fluid velocity provides the benefit of reduced friction loading; however, it also diminishes the water-lifting capability of the wellbore. Once the gas velocity has become too low to lift liquids, the liquids accumulate in the wellbore, and the well is said to be “liquid loaded”. This accumulation of liquids results in increased bottomhole flowing pressures and reduced gas recoveries. In this situation, continued gas production from the well requires the use of mechanical methods and apparatus in order to remove liquids from the wellbore and to restore stable flow.
In summary, gas wellbores are subject to two types of loading: (1) friction loading and (2) liquid loading.
Friction loading is caused by fluid flowing up the production tubing at high velocity, and results in restricted formation drawdown. Friction loading typically will not “kill” a well (i.e., completely halt the production of well fluids); however, it can significantly restrict production. The remedy or solution for friction loading is to reduce fluid velocities—e.g., by reducing gas flow rates (thus reducing gas velocity), or by increasing production chamber size while maintaining flow rates (thus reducing gas velocity).
Liquid loading is caused by insufficient fluid velocity up the production tubing. Like friction loading, liquid loading results in restricted formation drawdown. Liquid loading will eventually result in the well being killed. Any time a wellbore is “killed” (i.e., its production of well fluids is stopped) due to excessive liquids, considerable costs must be incurred to correct the problem and restore production from the well.
As discussed above, liquid loading can be reduced or eliminated by increasing fluid flow velocity to produce velocity-induced flow conditions. However, increased flow velocity also promotes increased friction loading. Current wellbore design methods typically provide excess flow velocity (i.e., significantly higher than VCR) to eliminate liquid loading and ensure that the well does not die. The resultant friction loading is accepted as the lesser of two evils.
In order to maintain long-term stable production rates from any gas well, the first priority is to ensure that the wellbore is substantially free from accumulation of liquids. If liquids production is substantial, any accumulation of liquids in the wellbore must be removed, either continuously or intermittently depending on the rate of accumulation. In cases where liquids are removed on an intermittent basis, the well would alternate between production and clean-out cycles, with the clean-out cycle beginning when accumulated liquids reach an undesirable level, and with gas production necessarily being stopped during the clean-out cycle.
In accordance with the preceding discussion, it can be appreciated that production optimization for a gas well requiring removal of liquids can be achieved by keeping the fluid velocity as close as practically possible to the well's critical velocity, in order to prevent accumulation of liquids while minimizing friction loading.
U.S. Pat. No. 6,991,034 and corresponding International Application No. PCT/CA2004/000478 teach methods and apparatus for enhancing natural gas well productivity by maintaining a velocity-induced flow regime, thus providing for continuous removal of liquids from the well and preventing or mitigating liquid loading and friction loading of the well. In accordance with U.S. Pat. No. 6,991,034, a supplementary pressurized gas is injected into a first (or injection) chamber of a gas well as necessary to keep the total upward gas flow rate in a second (or production) chamber of the well at or above a minimum flow rate needed to lift liquids within the upward gas flow. A cased well having a string of tubing may be considered as having two chambers (namely, the bore of the tubing, and the annulus between the tubing and the casing), and either of these chambers can serve as the first (or injection) chamber, with the other serving as the second (or production) chamber.
The invention of U.S. Pat. No. 6,991,034 provides for a gas injection pipeline, for injecting the supplemental gas into the injection chamber, and further provides a throttling valve (also referred to as a “choke”) for controlling the rate of gas injection, and, more specifically, for maintaining a gas injection rate sufficient to keep the gas flowing up the production chamber at or above a set point established with reference to a critical flow rate. Strictly speaking, the critical flow rate is a well-specific gas velocity above which liquids will not drop out of an upward-flowing gas stream (as previously explained). However, the critical flow rate for a given wellbore may also be expressed in terms of volumetric flow based on the critical gas velocity and the cross-sectional area of the production chamber.
As explained in U.S. Pat. No. 6,991,034, the critical flow rate for a particular well may be determined using methods or formulae well known to those skilled in the art. A “set point” (i.e., minimum rate of total gas flow in the production chamber) is then selected, for purposes of controlling the operation of the choke. The set point may correspond to the critical flow rate, but more typically will correspond to a value higher than the critical flow rate, in order to provide a margin of safety. Once the well has been brought into production, an actual total gas flow rate in the production chamber is measured. If the measured total gas flow rate (without gas injection) is at or above the set point, the choke will remain closed, and no gas will be injected into the well. However, if the measured total gas flow rate is below the set point, the choke will be opened so that gas is injected into the injection chamber at a sufficient rate to raise the total gas flow rate in the production chamber to a level at or above the set point.
Gas productions systems as taught in U.S. Pat. No. 6,991,034 may be referred to as fixed-velocity production systems.
U.S. Pat. No. 7,275,599 (and corresponding International Application No. PCT/CA2004/001567) teach methods and apparatus whereby the intake pipeline running between the production chamber of a natural gas well and the suction inlet of an associated wellhead compressor is completely enclosed within a vapour-tight jacket of natural gas under positive pressure (i.e., greater than atmospheric pressure). Being enclosed inside this “positive-pressure jacket”, the intake pipeline is “blanketed” with positive-pressure gas and therefore is not exposed to the atmosphere at any point. This allows gas to be drawn into the compressor through the intake pipeline under a negative pressure (i.e., lower than atmospheric pressure), without risk of air entering the intake pipeline should a leak occur in the pipeline. If such a leak occurs, there would merely be a harmless transfer of gas from the positive pressure jacket into the intake pipeline. Should a leak develop in the positive pressure jacket, gas therefrom will escape into the atmosphere, and entry of air into the positive pressure jacket will be impossible. As taught in U.S. Pat. No. 7,275,599, these teachings can be readily adapted for use in conjunction with wells producing gas under velocity-induced flow conditions in accordance with methods taught in U.S. Pat. No. 6,991,034.
Extensive scientific research has developed a number of flow correlations that predict downhole velocities in flowing wellbores. The oil and gas industry relies on these correlations to predict critical flow rates, and attempts to design production tubing strings such that fluid velocities will equal or exceed predicted critical velocities. However, experience with wellbore modeling indicates that some wells are capable of lifting liquids at velocities considerably below the predicted critical velocity, and some wells can become liquid loaded despite producing at fluid velocities well above the predicted critical velocity.
The ideal solution for optimizing a wellbore producing with a fixed-velocity lift system is to determine whether it requires continuous liquids removal, or whether it would be more optimally produced at velocities below critical with reduced friction loading, accompanied by intermittent removal of liquids. In other words, a well that liquid-loads over a period of (for example) ten days would benefit from intermittent clean-outs, while a well that loads over a period of one hour would require continuous liquids removal.
For the foregoing reasons, there is a need for systems and methods for:                automatically determining whether continuous or intermittent clean-out of liquids is the optimal production mode for a given wellbore, having regard to wellbore and formation properties;        automatically determining the optimum duration of production and clean-out cycles for wells utilizing an intermittent clean-out system;        automatically determining the optimal production chamber (e.g., either the tubing or the casing annulus), and switching fluid flow in the wellbore accordingly; and        automatically determining actual critical velocities for producing wellbores, and for maintaining the set point substantially equal to the actual critical velocities for wellbores utilizing a continuous clean-out system.        
Any system or method directed to the foregoing needs will necessarily entail use of flow control devices. Control valves of various types are commonly used to control the flow of both liquid and gaseous fluids. Flow control may be achieved using a control valve in combination with a controller (i.e., a device incorporating a processor and a memory, such as but not limited to a pneumatic controller or a programmable logic controller (PLC)) that compare one or more flow variables (such as but not limited to flow rate, pressure, and temperature) against pre-established values (or “set points”). In response to corresponding signals from the controller, the control valve either opens (partially or fully) or closes as necessary to maintain the flow variable(s) in question at the appropriate set point(s).
As used in this patent document, the term “control valve” may be understood as referring to either a discrete control valve or to a control valve assembly that incorporates a control valve, according to the context. A typical conventional control valve assembly (such as, for example, the Fisher® D (globe-style) or DA (angle-style) valve) includes a valve body, internal valve trim (“valve trim” being a term readily understood by persons skilled in the art), and a valve actuator. A conventional control valve assembly will commonly be provided in conjunction with additional accessories such as (but not limited to) positioners and proportional controllers. These accessories provide a means to enter a control set point for the control valve. Each configuration for a conventional control valve typically provides a relatively narrow capacity range for a given set of process conditions. Due to this narrow capacity range and the inherent complexity of the control valve, maintenance and design must be done by professional instrumentation personnel. As a result, conventional control valves are relatively expensive to purchase and maintain.
Most if not all control valves commonly used in the natural gas industry are pneumatically driven, and their operation typically results in the venting of methane gas to the atmosphere. In the past, this undesirable operational characteristic was considered tolerable in view of the reliability of such pneumatically-actuated control valves. However, with the increasing focus on reducing greenhouse gas emissions and improving system efficiencies, there is an increasing incentive to find environmentally-friendly alternative methods and apparatus for controlling fluid flow and pressure.
Electric actuators can be used to eliminate the venting of gas. However, electric actuators are comparatively expensive and have significant electrical power requirements, with correspondingly high operating costs.
For the foregoing reasons, it is desirable to have a comparatively simple and inexpensive control valve that can control fluid flow effectively under a broad range of process conditions with minimal power consumption and absolutely no external venting of gas. Such a control valve would ideally be serviceable by any ordinarily-skilled field personnel using comparatively inexpensive non-precision parts.
One known type of non-venting control valve is a bladder-type valve such as the “Sur-Flo”™ control valve manufactured by Sur-Flo Meters & Controls Ltd., of Calgary, Alberta, Canada. A typical bladder-type valve of the Sur-Flo™ type has a valve core comprising a pair of frustoconical sections configured much like common pails, each having a solid base at its small-diameter end and with its large-diameter end being open, but with its conical sidewall having a plurality of perforations. The two frustoconical sections are coaxially arranged inside a generally cylindrical valve housing, with their bases in close juxtaposition. A generally cylindrical elastomer sleeve (or “bladder”) is disposed within the valve housing, completely encircling the frustoconical sections, and a pressure port is provided through the cylindrical sidewall of the valve housing.
When this valve assembly is installed in a fluid flow line, and when there is no external pressure acting on the bladder through the pressure port, fluid can flow freely into the first frustoconical section and out through that section's sidewall perforations into the space between the frustoconical sections and the bladder, and then into the second frustoconical section through its sidewall perforations. However, if sufficient external fluid pressure is applied against the bladder via the pressure port (such as from a “volume bottle” or “expansion bottle” of well-known type, or from another pressure source), the bladder will contract against the frustoconical sections, sealing off their sidewall perforations, and thus preventing fluid flow through the valve assembly. At lower external fluid pressures, the bladder will restrict but not completely prevent fluid flow through the valve. Accordingly, flow through the valve can be incrementally controlled across the range between the fully-closed and fully-open position by varying the fluid pressure applied against the bladder via the pressure port, with the degree of flow restriction being roughly proportional to the external pressure acting against the bladder.
The bladder-type control valve is a comparatively simple non-venting valve that provides a wide range of flow control options under any process conditions. This valve is considerably less expensive than more complex control valves commonly in use, and it is readily serviceable by ordinarily skilled field personnel. This type of valve has proven durability and is very commonly used as a fixed-set-point back-pressure valve.
What is needed is an inexpensive adaptation of the bladder-type control valve that converts the simple fixed-set-point control valve to a variable-set-point control valve, thereby providing control of both flow and pressure. Such operational capabilities will be particularly beneficial in control valves used in conjunction with methods and apparatus for optimizing production in natural gas wells, but will be beneficial for purposes of other control valve applications as well.